COC rbc-jan-10-2011-industry.pdf

INDUSTRY |COMMENT
JANUARY 10, 2011
GRRRRRowth = High Voltage Investment
(Good Regs+Retrofit+Retire&Replace+Renewables)
We take a refined regulatory view in evaluating the industry and then layer in
growth, dividends, and unregulated subsidiaries. A strong regulatory
environment must be considered in tandem with growth profiles of utility
companies. If a proper regulatory foundation is not in place, growth can
actually impair the financial health of utilities. Given regulatory constructs,
growth prospects, upcoming catalysts and current valuations, we expect CMS,
NVE, PNM and SO to outperform the space in 2011.
Key Drivers of Favorable Regulatory Environments Include:
Small, simple, and routine general rate cases:General rate cases typically
weigh down utility stocks until resolved. Keeping requests small, stripping out
as many elements as possible, and filing them regularly minimizes rate case
risk and benefits shareholders.
Forward ratemaking = ROE realization:Eliminating regulatory lag with
forward ratemaking enables companies to realize approved ROEs on a
consistent basis.
Getting rewarded for large-scale investment risk:Receiving specific
approval for large projects, recovery of financing costs during construction,
and automatic inclusion in rates once online reduce financing costs and
support ROE realization.
Key Near Term Growth Topics Include:
Environmental Compliance spending still job #1:EPA final rulemaking in
2011 should prompt utilities to finalize fleet compliance plans. Retrofits,
retirements, and replacement capacity should comprise a bulk of utility capital
spending in the near term.
Build Green:Companies operating in states with Renewable Portfolio
Standards (RPS) can add to rate base by building the required generation or
associated transmission under these mandates.
Load Growth, still playing catch-up for now:Industrial volumes are up
thus far in 2010, but remain well below recent levels. We expect the positive
trending to continue, but likely not enough to trigger new capacity capital
spending in the near term.
Other Utility Considerations:
Steady and growing dividend:Dividends remain the backbone of utility
investing. Barring substantial catalysts, dividend yields must remain
competitive with current averages of 4.3%.
Unregulated Subsidiaries tip the scale:These segments represent an X
factor that could swing investor sentiment in one direction or another. We
prefer unregulated operations that 1) provide steady cash flows, 2) do not
introduce considerable risk, 3) overlap with existing utility expertise, and 4)
present growth opportunities.
Priced as of prior trading day's market close, EST (unless otherwise noted).
All values in USD unless otherwise noted.
RBC Capital Markets, LLC
Emily Christy (Analyst)
[phone]; [e-mail]
Lasan Johong (Analyst)
[phone]; [e-mail]
Ella Vuernick (Associate)
[phone]; [e-mail]
Companies under Coverage:
(Company, Ticker, Rating*, Current Price, Target
Price, Risk)
*O=Outperform, SP- Sector Perform, U=
Underperform
For Required Conflicts Disclosures, see Page 28.
2
Emily’s Scouting Report
We examine four major business drivers when evaluating regulated utilities: 1) regulatory environment, 2) growth prospects, 3)
unregulated subsidiary contribution, and 4) dividends. In this note we will examine these four business drivers and provide both
industry and company outlooks across our covered universe. Emily’s Scouting Report below summarizes our conclusions. Shading
reflects our view on which elements should improve (green) or worsen (red) in 2011. An expanded version with the supporting data is
found in Exhibit 15 on page 15 of this note. We intend to use this report as an ongoing measure of our views on the evolving industry
and company trends.
Exhibit 1: Emily’s Scouting Report
Regulatory
Rating1
General Rate
Cases
Forward/
Historical
Ratemaking
Treatment of
Large-Scale
Investments
Realized
ROE Key Rating Drivers
CMS O ++==+==Transformational story
NVE O +==--NA -Rate relief should increase ROE
PNM O ++=-=+-Regulatory progress = investor confidence
SO O ++++=++Industry-leading fundamentals
TE SP =+=+--=Coal risk
UTL SP =-NA -==+Rate case risk in new region
DTE SP =+====+Rate case risk, Energy Trading
DUK SP =-=-+-+Rate case risk, IN investigation
NEE SP -+=+++=Regulatory overhang, quiet subs
IDA U -===+NA -Rate case risk, weak dividend
Unregulated
Subsidiaries
Dividend
Yield
Growth

1) O= Outperform, SP= Sector Perform, U= Underperform
Source: RBC Capital Markets, Company reports, FactSet
1) Regulatory Environment: They Say Who, They Say When, They Say How Much
A supportive regulatory environment is paramount to utility financial health. Operating expenses are only recovered to the extent
regulators approve the costs. Growth can only benefit shareholders if regulators allow the utility to recover capital costs and earn
favorable returns on investments. Having a reasonable allowed ROE and mechanisms in place to realize it are hallmarks of favorable
regulatory environments. The most important elements of a regulatory structure toward that end are:
a) Small, simple, and routine general rate cases;
b) Forward ratemaking; and
c) Separate treatment of large-scale investments with pre-approval and recovery of costs during construction.
We examine these elements one by one and address the associated regulatory metrics found in Exhibit 1, the covered universe
snapshot. Shaded columns in the following regulatory exhibits are found in the snapshot.
We also examine smaller regulatory considerations including temporary rate structures, decoupling, and regulatory treatment of
energy efficiency.
a) General Rate Cases: Shrinking the Elephant in the Room
When a company submits a general rate case, all eyes focus on the regulatory environment and investors in the stock typically stay on
the sidelines until the rate case is resolved. This impacts utilities that only operate in one jurisdiction to a much greater extent than
those companies with diversified regulatory exposure. Utilities can minimize this rate case risk in certain jurisdictions by keeping
increases small, focused, and frequent enough to be handled as a matter of routine. Additionally, quick resolution of rate cases is
preferable. When these factors are present, rate case success rates are typically above the average ~60% mark. Recent rate case results
from across our coverage universe are found in Exhibit 2 at the end of this section.
Regulatory Structural Support in Simplifying Rate Cases
General rate cases are typically more successful when they are stripped of as many recovery elements as possible. Jurisdictions that
exclude costs for new generation, environmental retrofits, energy efficiency programs, and fuel expenses are generally preferred. This
GRRRRRowth = High Voltage InvestmentJanuary 10, 2011
3
keeps the rate case digestible for regulators, the increases smaller for ratepayers, and the process less risky for investors. Regulatory
models that embrace this structure include Alabama, Florida, Indiana, and Mississippi.
Favorable Rate Case Strategies
Frequent Filings
Aside from the structure elements of a particular jurisdiction, in many cases utilities can file rate cases at their discretion. Frequent rate
cases can reduce regulatory risk. If regulators become familiar with the utility needs on a regular basis, rate cases become more
manageable. Additionally, if rate cases occur more often, the requested increases are typically smaller. Small increases every year
raise less intervener eyebrows than larger increases every few years. That being said, fully litigated rate cases filed annually can cause
regulatory fatigue. This is particularly a risk if the rate cases are not simplified.
A clear example of this model in recent rate cases is PNM. The company filed its first rate case in over 20 years in 2007 and received
44% of its request. The initial staff recommendation was only 16%. PNM filed another rate case the following year and was awarded
69% of its request.
Settlement Instead Of Litigation
Rate cases that conclude in six months or less reduce the risk overhang of the rate case process. While few jurisdictions operate within
this short time frame, utilities can settle cases to shorten the process. Across our coverage, settled rate cases have lasted an average of
200 days, compared to 300 days for fully litigated rate cases. Additionally, utilities typically do not settle unless the outcome is
reasonable. An acceptable outcome and a shortened process bodes well for shareholders.
Exhibit 2: General Rate Case Summary

Rate
Case
Revenue Increase
($MM) % of Allowed Days to
Rating Subsidiary Year Requested Approved Request ROE Resolve
CMS O CMS Electric - MI 2010 $178 $146 82.0% 10.7% 287
CMS Gas - MI 2010 $89 $66 74.2% 10.6% 360
NVE O NVE - South - NV 2009 $311 $223 71.7% 10.5% 205
NVE-North - NV 2008 $111 $87 78.4% 10.6% 210
PNM O PNM Electric - NM 2009 $111 $77 69.4% 10.5% 248
TNMP - TX 2010 $20 $10 51.0% 10.1% 106
SO O Georgia Power - GA 2010 $809 $562 69.5% 11.2% 173
DTE SP Detroit Edison - MI 2010 $378 $217 57.4% 11.0% 350
MichCon - MI 2010 $171 $119 69.6% 11.0% 359
DUK SP Electric - NC 2009 $496 $315 63.5% 10.7% 140
Electric - SC 2009 $133 $74 55.6% 11.0% 120
Gas - KY 2009 $18 $13 74.3% 10.4% 159
Electric - OH 2009 $86 $55 64.0% 10.6% 279
Gas - OH 2008 $34 $18 53.4% 10.6% 255
NEE SP FPL - FL 2010 $1,000 $75 7.5% 10.0% 364
TE SP Tampa Electric - FL 2009 $228 $138 60.5% 11.3% 218
Peoples Gas - FL 2009 $27 $19 72.5% 10.8% 267
IDA U Idaho Power - ID 2009 $67 $27 40.3% 9.5% 219
Blended Metrics 63.2% 10.7% 241

Source: Company reports, RBC Capital Markets
GRRRRRowth = High Voltage InvestmentJanuary 10, 2011
4
b) Forward Test Year Crucial To Eliminating Regulatory Lag
Regulatory Lag Lowers ROEs
Regulatory lag is usually the prime culprit when utilities fall short of realizing their approved ROEs. When utilities request rates based
on the previous year’s costs, anything added to the portfolio in the coming year will not be recovered in rates until the following year.
Up to 12 months of O&M for a new power plant that is not included in rates can make a considerable impact to earnings. In other
words, shareholders, not customers may pay for the first year of expenses. Forward ratemaking is thus a critical part of the regulatory
construct. The correlation between forward ratemaking and realized ROE is clearly shown in Exhibit 3.
Exhibit 3: Impact of Regulatory Lag on Realized ROE
Rating
Forward/
Historical
Ratemaking
2009
Realized
ROE
NEE SP Forward 12.7%
SO O Forward 12.3%
TE SP Forward 10.9%
CMS O Forward 10.2%
IDA U Forward 8.9%
DTE SP Forward 8.6%
DUK SP Historical 7.3%
UTL SP Historical 7.1%
NVE O Hybrid 5.4%
PNM* O Forward 4.4%

*Forward test year being implemented
for the first time in PNM's pending rate
case
Source: RBC Capital Markets, Company reports, FactSet
ROE Band Protects Consumers, Regulators and Companies with Forward Ratemaking
Some regulators are hesitant to let utilities charge customers for expenses than have not been incurred. This can manifest through
outright denial of the structure, or in regulator pushback on forecasting methodology. The most productive construct for meeting this
challenge is using an ROE band. Under this structure, costs are projected based on earning within the band for the upcoming year(s).
If utilities earn above the band, the surplus can be credited back to customers, thus providing a safety net of sorts for regulators.
Utilities are incentivized to hit the top of the ROE band, and customers share in the spoils if utilities earn above the approved level.
Alabama uses ROE band methodology, Florida and Idaho use it for existing temporary rates.
c) Large Investments Require Additional Regulatory Support to Maintain Favorable ROEs
Failure to earn an allowed ROE can be magnified when utilities make large-scale capital investments. Financing costs incurred during
the construction phase are borne by shareholders unless certain regulatory structures are in place. In certain jurisdictions, utilities can
recover Allowance for Funds Used During Construction (AFUDC) or include Construction While In Progress (CWIP) in rate base
until the plant comes online. For high growth utilities, this regulatory support closes the gap between realized and approved ROE.
Investing large amounts of capital in a new power plant is burdensome for utilities, particularly in the midst of a struggling economy.
Regulatory structures can reduce the risks of large-scale investments by establishing a long-term planning forecast, pre-approving new
capacity, and allowing the aforementioned AFUDC or CWIP in rate base during the construction phase. Ideally, these investments are
also considered outside of a general rate case and costs can be recovered immediately once the plant comes online.
These parameters are often established on a per project basis, but our general views on the regulatory climates for these investments
across our coverage universe are found in Exhibit 4.
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5
Integrated Resource Plans (IRPs), and the Like
Many jurisdictions require utilities to file 10-20 year plans outlining capacity, transmission and other system needs. Needs are based
on load growth forecasts and updated on a regular basis. These plans give regulators the longer term picture and minimize surprises
when new projects are proposed. The routine filings create a window into utility expectations and keep regulators familiar with the
bigger picture.
Pre-Approval of Large-Scale Projects
Most jurisdictions provide a framework for approving major capital projects proposed by the utilities. Certifications that include cost
approvals are preferred. Few, if any, of these structures guarantee full cost recovery and timely inclusion in rate case. Although this
would be ideal, pre-approval certification generally provides enough surety for utilities to secure reasonable financing terms for the
project.
AFUDC/CWIP
The ability to recover financing costs during construction of a large-scale investment reduces the financial strain on the utilities and
supports realization of the approved ROE. Either recognition of AFUDC or the inclusion of CWIP in rate base accomplishes this end
satisfactorily. These mechanisms also help utilities secure financing at favorable terms.
Exhibit 4: Treatment of Large-Scale Investments
Rating
Treatment of
Large-Scale
Investments
CMS O Neutral
NVE O Mixed
PNM O Neutral
SO O Favorable

TE SP Mixed
UTL SP NA
DTE SP Neutral
DUK SP Mixed
NEE SP Mixed

IDA UP Neutral
Source: RBC Capital Markets, Company reports
Other Regulatory Trends:
Bandaid Ratemaking: Not Always a Cure
Given weak electricity demand during the recession, many utilities earned less than their approved ROEs in 2009/2010. In order to
balance the needs of the utilities with affordability for customers, some jurisdictions implemented temporary solutions. These rate
mechanisms essentially allow the utilities to borrow from balance sheet surplus items to maintain minimum ROEs. While providing
earnings support in the near term, we believe that this bandaid ratemaking can create dangerous precedents in the medium and longer
terms.
A Disconnect Is Born
Under these fixes, approved rates do not reflect the costs of utility service. After the short term fix expires, the original rate deficiency
must be added to bills, plus likely increases in costs since the original filing. This creates a bigger rate case the next time around. It
seems unlikely that consumer advocates will give the utility credit in hindsight for sparing customers during the previous period. The
advocates instead will challenge the higher requested rates. The post-bandaid rate case cycle thus sets up in contrast to our preferred
rate case model of small, simple asks.
In our coverage universe, IDA and NEE currently operate under temporary rate relief mechanisms. In NEE’s case, the utility can
recognize surplus depreciation up to certain amounts in order to reach a minimum ROE. IDA can recognize tax credits towards the
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6
same end. IDA is expected to file at rate case in 2011 and NEE in 2012. Both IDA and NEE have new generation costs in addition to
previous rate deficiencies to include in their respective filings. Without significant economic growth in either jurisdiction, the next rate
case cycles may be challenging.
Decoupling: Longer Term Agnostic, But In Rising Markets It May Hold Utilities in Check
Utilities that were decoupled in 2008 and 2009 benefitted from this structure when electricity demand plummeted. However, as
markets stabilize and trends move upward, these same utilities will not be as levered to the rising tide. At this point, we expect
companies without full decoupling to outperform decoupled utilities in 2011. Furthermore, when utilities are decoupled, the rates set
by regulators are increasingly important. As electricity load grows, the companies do not realize higher revenues without regulatory
approval.
Energy Efficiency: Recovery, Return, Incentives
The most supportive regulatory structures encourage energy efficiency at the utilities by treating costs outside of a general rate case,
assuring timely recovery of program costs, allowing a return on investment, and establishing earnings incentives for reaching certain
energy efficiency goals. Additionally, frameworks that provide for recovery of lost load due to energy efficiency rise above the rest.
This energy-efficiency-only decoupling removes the financial disincentives otherwise associated with energy efficiency programs.
Regulatory Conclusions: Detailed Snapshot
Below we have developed a regulatory matrix that captures a fuller view of the previously mentioned regulatory elements. We outline
our preferred model for these structures and view on favorable jurisdictions for each element. Additionally, we have developed these
matrices for each of our covered companies and their associated jurisdictions. They can be found in the appendix to this note, and in
the accompanying company notes published today.
Exhibit 5: Regulatory Matrix

Source: Company reports, RBC Capital Markets
2) Growth: Cleaning and Greening the Fleet
We categorize utility growth opportunities into three main baskets: a) Mandatory spending, b) Traditional spending, and c) Bells and
Whistles spending.
Regulatory Elements Our Preferred Model
Favorable Jurisdictions under
coverage for each element
Companies with
favorable exposure
General Rate Cases
Test Year Forward-looking AL, GA, FL, MS, MI, NM, ID NEE, SO, TE, CMS,DTE
Allowed ROE >10.5%, banded AL, GA, MS SO
Frequency & Duration File every 2-3 years AL, NV, GA, MS SO, NVE
<6 month decision process
Success rate >60%NV, MI, GA SO, NVE, CMS
(% of request approved)
Other Regulatory Mechanisms
Decoupling Energy-efficiency-only NM, NV, NC, SC, IN PNM, NVE, DUK
Other Recovery Mechanisms (non-rate case) The more the better FL, GA, AL, MI, IN NEE, TE, SO, CMS, DTE
Treatment of Capital Projects Long-term planning process GA, MS, FL, ID, MI, IN SO, NEE, IDA
Commission Pre-approval
Recovery of AFUDC
Cost recovery via rider
Fuel and Purchased Power 100% pass-thru Only ID falls short of 100%All but IDA
Cost recovery via rider (RR)
<= Annual recovery
Energy Efficiency Recovery of program costs NV, NM, NC, SC, IN NVE, PNM, DUK
Recovery of lost revenues
Earnings incentives
Commission Appointed Most except PNM
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7
a) Mandatory spending includes investments that are necessary to comply with laws and regulations. In the near term we expect
most utility growth projects to revolve around mandatory spending in the form of environmental compliance and Renewable
Energy Portfolio (RPS) compliance.
b) Traditional spending includes items associated with load growth such as new meters and new capacity. Plans for incremental
new capacity have mostly been shelved due to lower demand forecasts, but resumption of load growth could bring this basket
into utility outlook discussions in 2011.
c) Bells and Whistles spending includes investments that are not necessary in providing utility service, such as smart meters and
electric vehicle investments. Smart metering should proceed where it is already planned, but we do not expect new
investments in this area across the space in 2011. Electric vehicle infrastructure may make some headlines, but we do not
expect these investments on a significant scale in the near term.
To compare growth prospects across our universe we use our five-year forward capital spending estimates as a percentage of current
enterprise value. This growth metric is shown for our covered companies in Exhibit 6. Although absolute growth levels are important,
they must be considered in the context of the associated regulatory environment. Capital spending is only beneficial to the extent that
it is reflected in utility revenues, as approved by regulators.
Exhibit 6: Growth Metrics
Rating
5yr Capex/
Enterprise
Value
NEE SP 59%
DUK SP 58%
CMS O 58%
IDA U 55%
PNM O 53%
DTE SP 50%
UTL SP 48%
SO O 48%
NVE O 37%
TE SP 30%
Industry average = 45%
Source: RBC Capital Markets, Company reports, FactSet
a) Mandatory Spending
Environmental Compliance: You Must Clean It
EPA rulemaking in 2011 will likely prompt final fleet decisions by utilities. Over the next five years the resulting compliance plans
should occupy much of the total capital spending for the group. Most companies have already retrofit or plan to retrofit plants larger
than 400MWs to comply with current regulations. Plants under 200MW will likely be retired. It is the bubble plants of ~200-400MWs
that remain uncertain with respect to current regulations. A snapshot of company exposure to current regulations is below.
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8
Exhibit 7: Coal-at-Risk as % of Total Regulated Generating Capacity Under Current Regulations
0%
2%
4%
6%
8%
10%
12%
14%
16%
CMS DTE DUK IDA NEE NVE PNM SO TE

Source: Company reports, RBC Capital Markets
Decision-Making for Bubble Plants
Utilities have three basic options for the bubble plants: 1) retrofit with appropriate pollution controls, 2) run the plant until the
compliance period ends and then retire it, and 3) retire the plant and build new replacement capacity. Considerations for the above
include the age of the plant, reserve margins in the operating region, the severity of new regulations and the length of the compliance
period, and the regulatory environment for the different options. If new regulations push up the price of total compliance retrofits, it is
likely that bubble plants may lean more towards retirement.
Final Rulemaking for Environmental Regulations
Rulemaking in 2011/2012 revolves around four primary regulations currently being reviewed. Restrictions on NOx and SOx
emissions from the Clean Air Transport Rule (CATR), Maximum Achievable Control Technologies (MACT) under the Clean Air Act,
Coal Combustion Residuals (CCR) rules, and Section 316(b) under the Clean Water Act relating to cooling water intake structures.
While the first three regulations impact primarily coal plants, cooling water intake structures are a consideration for natural gas and
nuclear plants as well. Further descriptions of these rules and measures necessary for compliance can be found in Appendix C.
Mercury Scenario, In Particular May Present Additional Spending Opportunities
Current SOx and NOx restrictions have prompted most companies to add scrubbers and Selective Catalytic Reduction controls to
reduce emissions. These retrofits also typically reduce mercury emissions by 80%-85%. The mercury rule that is pending final
approval in March 2011 could increase this mercury threshold to >90%. Technology exists to meet this standard in the form of
Activated Carbon Injection (ACI) and baghouses at ~$150/kw. In our covered universe, PNM, DUK, and SO would have the most
capacity that would fall out of compliance if the new standard is greater than 90%, as shown below.
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9
Exhibit 8: Coal-at-Risk as % of Total Regulated Generating Capacity Under Two Mercury Scenarios
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
CMS DTE DUK IDA NEE NVE PNM SO TE
Mercury removal of 80-85%Mercury removal of >90%

Source: RBC Capital Markets, Company reports
Circling Back To Regulatory Frameworks In Assessing Compliance Spending Opportunities
There is no broad stroke that will apply to all utilities when fleet decisions are made. However, those with solid regulatory support
should rise above the rest. In the strictest mercury case, for example, DUK and SO would have considerable investments to make. SO
has forward ratemaking, a favorable rate case track record, above average ROEs and environmental compliance investments are
considered outside of the general rate case process. Considering these factors, environmental spending represents significant earnings
potential. Contrasting this model, DUK incurs regulatory lag across its jurisdictions and has average approved ROEs, average rate
case results and environmental spending is included in the general rate case process. Although compliance spending will ultimately
flow into rates, DUK shareholders will incur some of the costs along the way.
Renewable Energy Investments: If You Must, Green It
Over half of the states have Renewable Portfolio Standards (RPS) which mandates certain amounts of electricity that must be derived
from renewable energy sources. These mandates create opportunities for utilities to grow their rate base despite low consumption
forecasts. Most notably in our coverage, NVE, PNM, DTE, and CMS should benefit from investing in renewable energy.
Additionally, unregulated subsidiaries at DUK and NEE benefit from renewables growth.
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Exhibit 9: Renewable Portfolio Standards Impacting Our Coverage Universe
State
%
Renewable by Year Notes
NV 25% 2025 - 5% of requirement must be solar through 2015
- 6% must be solar as of 2016
- Energy Efficiency can be up to 25% of requirement
- Progression: 15% by 2011, 18% by 2013, 20% by 2015, 22% by 2020
MI 10% 2015 - Detroit Edison: 300MW of new renewables by 2013 and 600MW by 2015
- Consumers Energy: 200MW of new renewables by 2013 and 500MW by 2015

- Existing renewable energy baseline plus 20%, 33%, 50% of the gap between baseline and
10% in 2012, 2013 and 2014 respectively
NC 12.5% 2021 - Solar: 0.2% by 2018
- Energy Efficiency can be up to 25% of requirement
- Energy Efficiency can be up to 40% of requirement after 2021
- Progression: 3% by 2012-2014, 6% by 2015, 10% by 2018
NM 20% 2020 - Solar: 20% of requirement (4% of sales)
- Wind: 20% of requirement (4% of sales)

- Geothermal, biomass, certain hydro facilities and other renewables: 10% of requirement
(2% of sales)
- Distributed renewables: 3% of requirement (0.6% of sales)
OH 12.5% 2025 - Renewables: 12.5% by 2024 (includes solar-electric minimum)
- Solar-Electric: 0.5% by 2024

- At least 50% of the renewable energy requirement must be met by in-state facilities, and
the remaining 50% with resources that can be shown to be deliverable into the state.

- Progression: 1% by 2011, 1.5% by 2012, 2% by 2013 and an additional 1% each year
thereafter
TX
10,000
MW 2015 - Non-Wind: Goal of 500 MW
- Progression: 4,264 MW by 2011, 5,256 MW by 2013 5,880 MW by 2015
Source: U.S. Department of Energy
Investing Directly In Renewable Generation
Utilities can typically choose between building the renewable generation or contracting for the energy from third parties. If regulators
are supportive, utilities benefit by building the generation and adding it to rate base. This is especially true with utilities that have
already acquired the necessary skill set for the renewable project. NEE, for example, develops renewable projects in its unregulated
subsidiary and is well-positioned to develop similar projects through its utility if FL establishes renewable energy standards. In other
cases, we prefer joint ventures with experienced partners until the utility develops the appropriate level of expertise. NVE practices the
latter with its wind and geothermal joint ventures. SO also has a solar joint venture.
Investing In Renewables Transmission
In addition to the renewable generation that is needed to satisfy these requirements, transmission lines are often needed to access the
generation. These investments overlap with existing utility expertise and typically provide solid returns. State regulators often prefer
utilities to construct and maintain these lines. Regulators can typically keep a closer eye on the utilities than on third party vendors.
When competing for these projects, utilities thus may have an advantage in the approval process. Given the availability of renewable
energy in NV and its proximity to the high demand market of CA, renewable transmission opportunities should emerge for NVE.
b) Traditional Spending
Load Growth: Still Playing Catch-Up
Weather-adjusted load growth turned positive in most jurisdictions in 2010 and we expect this trend to continue in 2011. Industrial
volumes carried the day for most utilities, with residential consumption following to a lesser degree. Also of note, 3Q10 results were
strong across the country due to favorable weather in most regions. This may create headwinds for 3Q comps, but over the longer term
investors should look beyond the weather impact and evaluate the adjusted load numbers.
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11
Industrial Volumes Up, But Still Below Recent Normals
Industrial volumes were up 7% over 2009 levels for most of the year, but still remain below average levels of the past 10 years.
Utilities operating in heavy industrial areas benefitted from the upsurge and still have room to grow. However, going into 2011 a
comparable 7% jump may be ambitious. We expect steady increases, but on a smaller scale than in 2010.
Exhibit 10: Industrial Volumes: 1990-August 2010
0.1%
2.8%
0.5%
3.2%
0.5%
2.1%0.7%
-6.4%
-0.6%
-12.6%
7.0%
0.6%
-1.8%
2.2%
0.5%
0.1%
1.6%0.4%1.3%
-0.7%
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
19
9
0
19
9
1
19
9
2
19
9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
0
9

Y
T
D
20
1
0

Y
T
D
-17.0%
-12.0%
-7.0%
-2.0%
3.0%
8.0%
Industrial Consumption (GWh)% Change

Source: U.S. Energy Information Administration, RBC Capital Markets
Non-Industrial Jurisdictions
Regions influenced by the housing market more than heavy industry, such as Florida and Las Vegas, have yet to experience a surge in
load growth. Housing metrics in these areas are improving, as seen in the charts below, but the glut of inventory from the housing
boom remains an issue. Although it still may take time for housing inventory to clear in some of these regions, directional positives
may be sufficient to renew investor interest.
Exhibit 11: S&P Case Shiller Home Price Indices
'91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10
0
50
100
150
200
250
300
Source: FactSet Prices
Indexed Price Performance Price (Indexed to 100)
US National CS Index Tampa CS Index Miami CS Index
Las Vegas CS Index
Source: FactSet
Growth Conclusion: Spending Likely Up From Here
The bulk of near term capital spending should pertain to environmental compliance. Considering additional emissions restrictions
expected in 2011/2012, we expect that this spending should only increase. Additionally, resumption of load growth across the country
should renew traditional spending programs. Although new capacity likely remains beyond the near term at current absolute levels, we
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12
expect utilities to begin discussing these needs in the next couple of years. Bullish capital spending outlooks support our rising
industry multiple for 2011.
3) Unregulated Subsidiaries
Unregulated subsidiaries of utilities represent an X factor that could swing investor sentiment in one direction or another. They can
make up for lack of utility growth or an unfavorable regulatory mechanism. They can also, however, introduce risk and narrow the
investor pool accordingly. We prefer unregulated operations that 1) provide steady cash flows, 2) do not introduce considerable risk,
3) overlap with existing utility expertise, and 4) present growth opportunities. To be considered as a utility first, unregulated subs
generally comprise less than 25% of the consolidated entity.
Steady Cash Flows: Utility-Like Subsidiaries
Energy subs that are heavily contracted over the longer term enhance utility earnings by providing stable returns. Energy infrastructure
entities match well with this preferred model. Unregulated generation can also be a fit, providing that commodity exposure is hedged
or contracted away. These businesses are typically well understood by utility companies and investors.
Marketing and Trading: Common Sub, Common Discount
Several utilities engage in marketing and trading commodities in an unregulated subsidiary. The companies are already engaged in
these markets in order to secure energy for customers. Extending the involvement into active trading outside of existing needs and
assets, however, introduces risks that do not sit well with investors. While strong risk parameters can minimize the downside, the
volatility of results cannot always be controlled. Investors rarely assign full credit to these operations.
Expertise Overlap
We prefer subs where a utility simply extends its core expertise into a related entity, as opposed to investing in new areas of expertise.
Spending a disproportionate amount of time on conference calls and presentation slides explaining unregulated subsidiaries detract
from the core utility fundamentals. These subs can complicate otherwise straightforward utility stories. Unless the regulated business
is well above average, investors are unlikely to take the time to understand and give full credit to a completely different business
model.
Growth Opportunities: Earnings Accretion Without Ratepayer Strain
Utility regulators and ratepayers only tolerate moderate increases from year to year. Unregulated subsidiaries can step in and
supplement growth for the consolidated entity. As long as the growth prospects do not add considerably to the utility risk profile,
shareholders can benefit from the expansion.
Standout Subsidiaries, In Both Directions
DTE’s gas pipelines and biomass development businesses, PNM’s First Choice Power retail arm, and the contracted wind assets of
DUK and NEE benefit shareholders. On the other hand, marketing and trading at DTE and NEE, and TE’s coal segment introduce too
much risk, in our view. A summary of unregulated subsidiaries that impact our covered names is found below in Exhibit 12.
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13
Exhibit 12: Unregulated Subsidiaries
Rating Subs Impacting Valuation
Overall
Rating
CMS O Contracted Generation Neutral
NVE O None NA
PNM O Retail electric Favorable
SO O Contracted Generation Favorable

TE SP Coal mining; Int'l plants Unfavorable
UTL SP None NA
DTE SP Energy Trading; Gas Infrastructure Neutral
DUK SP Merchant Generation; Int'l plants Unfavorable
NEE SP Contracted Generation;
Renewable development
Favorable

IDA U None NA
Source: RBC Capital Markets, Company reports
4) Dividend: Steady and Growing
In addition to regulatory considerations and growth profiles, utilities must have competitive dividend yields. Companies with strong
balance sheets are particularly well-positioned to support consistent, growth dividends. Given the long building cycle for power plants
and transmission lines, investors must be paid to wait. While upcoming catalysts can offset this need in the short term, longer term
investors put a premium on strong dividend yields.
Exhibit 13: Balance Sheet and Dividend Metrics

Total Debt
($MM)
Market Cap
($MM)
% Debt/Total
Cap
S&P500
Rating
Moody’s
Rating
Dividend
Yield
Duke Energy Corp. DUK $18,291 $23,497 44% A- Baa2 5.5%
Southern Co. SO $20,530 $31,777 48% A Baa1 4.8%
NextEra Energy Inc NEE $20,468 $21,804 51% A- Baa1 3.8%
Large Cap Average 49% 4.6%

PNM Resources Inc. PNM $1,760 $1,143 44% BB- Ba2 3.9%
IDACORP Inc. IDA $1,619 $1,823 47% BBB Baa2 3.2%
DTE Energy Co. DTE $8,017 $7,724 48% BBB+ Baa2 4.9%
Unitil Corp. UTL $335 $250 55% NA NA 6.0%
NV Energy Inc. NVE $5,670 $3,318 59% BB Ba3 3.1%
TECO Energy Inc. TE $3,417 $3,868 60% BBB Baa3 4.6%
CMS Energy Corp. CMS $7,234 $4,576 62% BBB- Ba1 4.5%
SMID Cap Average 54% 4.3%
Source: RBC Capital Markets, FactSet
Valuation Considerations and 2011 Outlook
We expect the large cap utilities to trade slightly above current levels in 2011 due to further resumption of load growth and increasing
capital spending forecasts as a result of EPA final rulemaking.
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14
• Current multiples are 12.6x for large caps and 12.9x for SMID caps. We expect multiples to improve ~5% to 13.3x 2012
earnings for large caps and to 13.5% 2012 earnings for SMID caps. Long term averages are 13.1x for large caps and 13.3x
for SMID caps.
• Utilities should benefit from continued weather-adjusted load growth recovery and capital spending increases.
• Large caps are more defensive with higher stock liquidity, stronger balance sheets and diversified regulatory platforms.
SMID caps, on the other hand, are more levered to economic recovery and we expect them to outperform accordingly.
Interest Rates: Ambiguous Multiples Correlation at Current Levels, But Rising Tide Should Lift All Boats
Although we do not base our industry multiples on interest rates, there has been industry discussion on the topic. Accordingly, we
believe it is beneficial to outline our view on interest rates.
Although RBC economists expect interest rates to rise in 2011, we believe that absolute yields are still below the threshold that would
impact utilities to a large degree. The most correlated interest rate entity has been the 10yr US Treasuries. Traditionally and
theoretically when interest rates rise, utility multiples fall. This has been the case historically until interest rates fall below ~5-6%.
Below these levels, however, the traditional negative correlation becomes fuzzy. In fact, as shown in the chart below, the two entities
are more positively correlated than negatively correlated below these levels.
RBC research forecasts interest rates on 10yr US Treasuries at 3.6% on average in 2011 and up to 4.5% in 2H12. Accordingly, we
believe that these levels suggest a continued positive correlation with utility multiples in the near term. Until interest rates rise to
compete with utility dividend yields, currently 4.5% on average, we expect both entities to rise together.
For more information on RBC’s interest rate forecast, please see the RBC note from 12/10/2010, “Financial Markets Monthly: Getting
ready for 2011.”
Exhibit 14: U.S. 10yr Treasury Yields vs. Large Cap Utility NTM P/Es
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9/95 8/96 6/97 4/98 2/99
12/9
9
10/0
0
08/0
1
06/0
2
05/0
3
03/0
4
01/0
5
11/0
5
09/0
6
07/0
7
05/0
8
03/09
01/10
12/10
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
14.0x
16.0x
18.0x
20.0x
10yr Treasury Yield Large Cap Utilities NTM P/E
Source: RBC Capital Markets, FactSet, US Federal Reserve
2011 Company Outlook:
We Expect CMS, NVE, PNM, and SO To Outperform The Space.
For more detailed views on these companies, please see our company notes of the same date.
Here again we review our coverage via the Scouting Report. The expanded version below provides the supporting date as described
throughout this note. Shading again reflects our view on elements that we expect to improve (green) or worsen (red) in 2011.
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Exhibit 15: Emily’s Expanded Scouting Report

Regulatory Growth Unregulated
Subsidiaries
Dividend
Yield
Rating1
RBC 2011
All-in
Return
Current P/E
Premium/
Discount2
General
Rate Case
Success
Forward/
Historical
Ratemaking
Treatment of
Large-Scale
Investments
2009
Realized
ROE
5yr Capex/
Enterprise
Value Key Rating Drivers
CMS O 15.5% -8.8% 82% Forward Neutral 10.2% 57% Neutral 4.5% Transformational story
NVE O 14.5% -8.6% 72% Hybrid Mixed 5.4% 37% NA 3.1% Rate relief should increase ROE
PNM O 17.3% -12.7% 69% Forward Neutral 4.4% 51% Favorable 3.8% Regulatory progress = investor confidence
SO O 12.6% 12.1% 70% Forward Favorable 12.3% 48% Favorable 4.9% Industry-leading fundamentals
TE SP 9.6% -7.4% 61% Forward Mixed 10.9% 29% Unfavorable 4.6% Coal risk
UTL SP 10.8% 4.7% 70% Historical NA 7.1% 47% NA 6.0% Rate case risk in new region
DTE SP 10.5% -8.3% 57% Forward Neutral 8.6% 50% Neutral 4.8% Rate case risk, Energy Trading
DUK SP 12.4% 1.4% 64% Historical Mixed 7.3% 58% Unfavorable 5.6% Rate case risk, IN investigation
NEE SP 9.4% -12.6% 8% Forward Mixed 12.7% 58% Favorable 4.1% Regulatory overhang, quiet subs
IDA U 8.0% -4.6% 43% Hybrid Neutral 8.9% 55% NA 3.3% Rate case risk, weak dividend
1) O= Outperform, SP= Sector Perform, U= Underperform
2) P/E premium/discount to either SMID Cap or Large Cap averages, as appropriate.
Source: RBC Capital Markets, Company reports, FactSet
CMS Energy Corp. (CMS): Outperform
Transformational Story, Quieter Regulatory Year, Fleet Decisions Possible
In recent years, CMS has ample growth opportunities and a favorable regulatory structure to support the capital spending plan. With
these fundamentals in place and the recent dividend increase, CMS’s current 9% trading discount is unwarranted and should improve
in 2011.
Key 2011 CMS Catalysts Include:
• Gas rate case decision
• Favorable realized ROE
• Continued investor turnover with increased dividend
Investment Risks:
• Unfavorable regulatory outcomes
• Decoupling lessens leverage to economic recovery
• Cost overruns on pollution control installation

NV Energy Inc. (NVE): Outperform
High Spend Transitioning Into Earnings Growth
NVE is winding down from a high capital spending phase and rate case activity in 2011 should translate these investments into
earnings growth. The company’s regulatory structure leaves room for improvement, but general rate case results have been favorable
to NVE. As the gap between approved and realized ROE narrows, NVE should outperform its peers. The company currently trades at
an (11%) discount to the group which should improve as rate relief comes into view.
Key 2011 NVE Catalysts Include:
• NV-N rate case decision
• Possible 1H11 equity issuance
• Closing of CA asset sale
• NV-S rate case filing
Investment Risks:
• Unfavorable regulatory outcomes
• Continued housing market weakness
• Equity issuance higher than expected

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PNM Resources, Inc. (PNM): Outperform
Catalyst Rich 2011 Marked By Regulatory Catch-Up
With favorable outcomes in its pending rate cases PNM should begin closing the gap between its authorized ROE and its realized
ROE in 2011. Furthermore, important precedents being considered in New Mexico and Texas could solidify the regulatory structures.
This would give investors and credit agencies greater confidence in the respective jurisdictions. Possible credit upgrades, dividend
increase discussions, and growth plans at PNM’s unregulated businesses are all likely on the table following reasonable regulatory
results. PNM currently trades at a (18%) discount to the group, which we expect to erode as positive catalysts are realized.
Key 2011 PNM Catalysts Include:
• Rate cases in NM, FERC
• Energy Efficiency incentives
• Solar development progress
Investment Risks:
• Unfavorable regulatory outcomes
• Continued economic weakness in NM, TX
• Margin pressure at First Choice Power

Southern Company (SO): Sector Perform
Favorable Regulatory Environment and Growth Prospects Already Priced In
Southern Company leads the industry in countless metrics. It demonstrates operational, financing, and development prowess across its
enterprises. These skills, combined with favorable regulatory frameworks and a solid growth pipeline position SO perpetually at the
top of the class.
Key 2011 SO Catalysts Include:
• AP1000 design certification, COL
• Vogtle 3&4 cost updates 2/11, 8/11
Investment Risks:
• Cost overruns and project delays
• Unfavorable regulatory outcomes
• Stricter than expected EPA timelines

IDACORP, Inc. (IDA): Underperform
Big Ask and Low Dividend Yield Present Challenges In 2011
After 2011, temporary rate support expires and tax settlement impacts go away. IDA then must face the existing rate deficiency on top
of new expenses associated with the Langley Gulch power plant. Given its recent rate case struggles and economic weakness in ID,
rate case risk may be elevated. Further out the company has favorable growth from transmission projects, but with the current low
dividend yield, investors are not being paid to wait for this growth to develop. Accordingly, we expect IDA to underperform the group
in the near term. IDA currently trades at a (4%) discount which adequately reflects the regulatory risk anticipated in 2011/2012.
Key 2011 IDA Catalysts Include:
• Rate case filing
• Tax settlement
Investment Risks:
• Unfavorable regulatory outcomes
• Decoupling lessens leverage to economic recovery
• Cost overruns at Langley Gulch power plant
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DTE Energy Co. (DTE): Sector Perform
Rate Case Activity Offsets Favorable Growth Profile in the Near Term
DTE is in the midst of a robust capital spending phase to bring its generation fleet up to increasingly strict environmental standards.
Although spending at these levels can strain the balance sheet, we believe that the constructive regulatory environment in MI should
minimize this risk and allow the company to realize steadily growing earnings and perform in line with peers.
Key 2011 DTE Catalysts Include:
• Rate case decision at electric utility
• Extension of Steel Industry Fuel tax credit
• Fleet decisions from EPA final rulemaking
Investment Risks:
• Unfavorable regulatory outcomes
• Continued weakness in natural gas prices
• Energy trading volatility

Duke Energy Corp. (DUK): Sector Perform
Regulatory Bumps Coming, But Investors Are Paid To Wait
Much attention has been paid to DUK’s OH customer switching issues and now focus is directed on the IN regulatory situation. With
the new ESP in OH and Edwardsport settlement resolution expected in the near term, investors should begin looking forward. After
winding down its environmental compliance program, rate relief, load growth and nuclear development should take center stage. We
believe that uplift from the OH and IN resolutions and the strong dividend yield may be offset by rate cases in the Carolinas in 2011
and expect DUK to perform in line with its peers accordingly.
Key 2011 DUK Catalysts Include:
• Carolina rate cases
• Legislative efforts to mitigate new nuclear risks
• Resolution of Edwardsport settlement agreement
Investment Risks:
• Unfavorable regulatory outcomes
• Cost overruns at construction projects
• Unfavorable final EPA rules

NextEra Energy Inc. (NEE): Sector Perform
Regulatory Headwinds Remain
NEE has withstood a considerable regulatory setback due to favorable non-rate case framework and support from its unregulated
operations. Going forward the utility remains highly levered to the FL economy with its anticipated 2012 rate case filing. Although
challenges remain for NEE, we believe that most of the stock damage has been done and expect NEE to trade with the group in 2011
as a Sector Perform.
Key 2011 NEE Catalysts Include:
• Improving economic trends
• New wind/solar project announcements
Investment Risks:
• Further weakness in FL economy
• Pullback in renewable energy mandates
• Sluggish power markets
TECO Energy Inc. (TE): Sector Perform
Florida Economic Recovery Pairs Well With Recent Rate Relief and Restructuring, but Coal Drag Likely To Persist
While FL economic recovery may be a slow climb, we anticipate positive trending in 2011. A resumption of load growth, the 2009
rate increase, lower cost structure and minimal capital spending needs should position the company favorably in 2011. However, TE’s
coal business offsets some of these drivers. We expect negative headlines and cost pressures to continue throughout the year and to
hold the stock in check with its peers.
Key 2011 TE Catalysts Include:
• Improving FL economic metrics
• Potential FL renewable energy legislation
• Potential new coal regulations
Investment Risks:
• Rising coal costs in Central Appalachia
• Continued weakness in FL economy
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Unitil Corp. (UTL): Sector Perform
Rate Case Risk Offset by Favorable Dividend Yield
UTL has been a dividend-play during the recession and associated market turmoil. Although the dividend will remain a critical part of
the picture, the company’s regulatory efforts should be the focus in 2011. We expect the regulatory risk associated with the rate case
activity to capture attention and keep UTL in check with its peers.
Key 2011 TE Catalysts Include:
• Rate cases in NH, MA and ME

Investment Risks:
• Unfavorable regulatory outcomes
• Severe weather events
• Weakness in New England economy

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Appendix A: Regulated Utilities Comparables
Valuation Regulatory Growth
Rating3
RBC 2011
All-in
Return
1/7/2011
Price
Target
Price
Dividend
Yield4
Current
Multiple
RBC Target
Multiple
Current
Premium/
Discount
RBC
Estimated
Premium/
Discount
RBC 2012
EPS
Estimate
General Rate
Case Success
Forward/
Historical
Ratemaking
Treatment of
Large-Scale
Investments
2009
Realized
ROE
5yr Capex/
Enterprise
Value Key Rating Drivers
RBC Risk
Rating
SMID Caps1
CMS O 15.5%$18.91 $21 4.5%11.9x 13.0x -8.7%-4.0%$1.59 82%Forward Neutral 10.2%57%Neutral Transformational story AVG
NVE O 7.5%$14.37 $16 3.1%11.9x 12.7x -8.6%-6.0%$1.21 72%Hybrid Mixed 5.4%37%NA Rate relief should increase ROE AVG
PNM O 9.8% $13.21 $15 3.8% 11.3x 12.2x -12.7% -10.0% $1.16 69%Forward5 Neutral 4.4% 52% Favorable Regulatory progress = investor confidence AVG
DTE SP 8.4%$46.34 $49 4.8%11.9x 12.4x -8.3%-8.0%$3.88 57%Forward Neutral 8.6%50%Neutral Rate case risk, Energy Trading AVG
TE SP 4.1%$18.09 $19 4.6%12.0x 12.2x -7.4%-10.0%$1.50 61%Forward Mixed 10.9%30%Unfavorable Coal risk AVG
UTL SP 10.8%$22.90 $24 6.0%13.6x 14.0x 4.7%4.0%$1.68 70%Historical NA 7.1%48%NA Rate case risk in new region AVG
IDA U 8.0%$37.22 $39 3.3%12.4x 13.1x -4.6%-3.0%$3.00 43%Hybrid Neutral 8.9%54%NA Rate case risk, weak dividend AVG
SMID Cap Peer Average SMID 4.3%13.0x 13.5x
Large Caps2
SO O 10.0%$38.08 $41 4.9%14.3x 15.2x 12.1%14.0%$2.67 70%Forward Favorable 12.3%48%Favorable Industry-leading fundamentals AVG
DUK SP 12.4%$17.79 $19 5.6%12.9x 13.4x 1.4%1.0%$1.38 64%Historical Mixed 7.3%58%Unfavorable Rate case risk, IN investigation AVG
NEE SP 9.4%$52.22 $55 4.1%11.1x 11.7x -12.6%-12.0%$4.70 8%Forward Mixed 12.7%58%Favorable Regulatory overhang, quiet subs AVG
Large Cap Peer Average 4.3%12.7x 13.3x
RBC EPS Estimates
1Q10 2Q10 3Q10 4Q10E 2010E 2011E 2012E
CMS $0.38 $0.26 $0.52 $0.20 $1.34 $1.43 $1.59
DTE $1.38 $0.39 $0.96 $0.80 $3.64 $3.69 $3.88
DUK $0.36 $0.34 $0.51 $0.23 $1.44 $1.32 $1.38
IDA $0.32 $0.30 $1.39 $0.53 $2.53 $2.79 $3.00
NEE $0.94 $1.11 $1.46 $0.83 $4.32 $4.45 $4.70
NVE -$0.01 $0.16 $0.77 -$0.06 $0.87 $1.01 $1.21
PNM $0.06 $0.21 $0.63 -$0.03 $0.88 $0.82 $1.16
SO $0.60 $0.61 $0.97 $0.20 $2.36 $2.49 $2.67
Unregulated
Subsidiaries
'06 '07 '08 '09 '10
40
50
60
70
80
90
100
110
120
130
140
Source: FactSet Prices
S&P 500 vs. SMID Caps vs. Large Caps Trailing 5 yrs
Indexed Price Performance Price (Indexed to 100)
S&P 500 SMID Caps Large Caps
SO $0.60 $0.61 $0.97 $0.20 $2.36 $2.49 $2.67
TE $0.34 $0.37 $0.41 $0.21 $1.33 $1.37 $1.50
UTL $0.60 -$0.19 -$0.01 $0.61 $1.02 $1.37 $1.68

1) SMID Cap Peer Group includes: AEE, BKH, CNP, CEG, NU, NST, OGE, POM, POR, PNY, PNW, UIL, WR and WEC, in addition to covered names.
2) Large Cap peer group includes: AEP, ED, D, PCG, PGN, SRE and XEL, in addition to covered names.
3) O=Outperform, SP=Sector Perform, U=Underperform
4) Based on RBC 2011 Dividend and EPS estimates and current prices
5) New rule, being implemented for the first time in PNM's rate case
Source: RBC Capital Markets estimates, FactSet
'06 '07 '08 '09 '10
40
50
60
70
80
90
100
110
120
130
140
Source: FactSet Prices
S&P 500 vs. SMID Caps vs. Large Caps Trailing 5 yrs
Indexed Price Performance Price (Indexed to 100)
S&P 500 SMID Caps Large Caps
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Appendix B: Regulatory Matrix for companies under coverage
CMS Regulatory Matrix
Regulatory Structure Elements Rating Our Preferred Model MI - 100%
General Rate Cases
Test Year ++++Forward-looking Forward-looking
Allowed ROE =>10.5%, banded 10.7%, unbanded
Frequency & Duration of rate cases =File every 2-3 years Filed annually
<6 month decision process 12 month decision process
Success rate (% of request approved)++++>60%80% blended, 2009-2010
Other Regulatory Elements
Decoupling —Energy-efficiency-only Full decoupling
Recovery Mechanisms outside of general
rate case process
++++The more the better Fuel, Energy Efficiency, Renewables
Treatment of Large Capital Projects =Long-term planning process Nothing formal
Pre-approval by Commission Certificate of Need process
AFUDC/CWIP in rate base AFUDC recovery
Cost recovery outside of base rates Recovery in base rates
Fuel and Purchased Power =100% pass-thru 100% pass-thru
Cost recovery outside of base rates Cost recovery outside of base rates
Reconciliation at least annually Reconciliation at least annually
Energy Efficiency ++++Recovery of program costs Recovery of program costs
Recovery of lost sales revenue Recovery of lost sales revenue
Earnings incentives Earnings incentives
Commission ++++Appointed Appointed
Source: RBC Capital Markets, Company reports
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DTE Regulatory Matrix
Regulatory Structure Elements Rating Our Preferred Model MI - 100%
General Rate Cases
Test Year +Forward-looking Forward-looking
Allowed ROE +>10.5%, banded 11.0%, unbanded
Frequency & Duration of rate cases =File every 2-3 years Filed ~annually
<6 month decision process 12 month decision process
Success rate (% of request approved)=>60%60% blended, 2009-2010
Other Regulatory Elements
Decoupling =Energy-efficiency-only (EE-only)Full decoupling, moving to EE-only
Recovery Mechanisms outside of general
rate case process
+The more the better Fuel, Energy Efficiency, Renewables
Treatment of Large Capital Projects =Long term planning process Nothing formal
Pre-approval by Commission Certificate of Need process
AFUDC/CWIP in rate base AFUDC recovery
Cost recovery outside of base rates Recovery in base rates
Fuel and Purchased Power =100% pass-thru 100% pass-thru
Cost recovery outside of base rates Cost recovery outside of base rates
Reconciliation at least annually Reconciliation at least annually
Energy Efficiency +Recovery of program costs Recovery of program costs
Recovery of lost sales revenue Recovery of lost sales revenue
Earnings incentives Earnings incentives
Commission +Appointed Appointed
Source: RBC Capital Markets, Company reports
DUK Regulatory Matrix
Regulatory Structure Elements
Blended
Rating Our Preferred Model NC - 49% rate base IN - 25% rate base SC - 15% rate base OH - 8% rate base KY - 3% rate base
General Rate Cases
Test Year -Forward-looking Historical Historical Historical Historical Historical
Allowed ROE =>10.5%, banded 10.70% 10.50% 11.00% 10.60% 10.40%
Frequency & Duration =File every 2-3 years Filed as needed Filed as needed, none since
merger
File as needed File as needed File as needed
<6 month decision process 5 months to settle in 2009 NA 4 months to settle in 2009 9 months in 2008 5 months 2008/2009
Success rate =>60% 63.5% in 2009 NA 55.0% 60.0% 74.0%
(% of request approved)
Other Regulatory Elements
Decoupling ++++Energy-efficiency-only Energy-efficiency-only Energy-efficiency-only Energy-efficiency-only Energy-efficiency-only None
Other Recovery Rechanisms
(non-rate case)
=The more the better Fuel, Energy Efficiency Fuel, Demand side
management, Smart Grid,
Pollution controls and
emissions, MISO costs
Fuel, Demand side
management, pension, storm
reserve, nuclear insurance
Fuel, environmental spending,
energy efficiency, smart grid,
bad debt, wind storm cost
recovery
Fuel
=Long-term planning process Integrated Resource Plan Integrated Resource Plan Integrated Resource Plan N/A - T&D only Integrated Resource Plan
Commission Pre-approval Certificate of Public
Convenience & Necessity
Certificate of Need Certificate of Need
Recovery of AFUDC CWIP in rate base, nuclear
development costs
IGCC costs recovered as
incurred
Nuclear CWIP via rider
Cost recovery via rider Included in base rates Rider for IGCC CWIP Included in base rates Included in base rates
Fuel and Purchased Power =100% pass-thru 100% pass-thru 100% pass-thru 100% pass-thru 100% pass-thru 100% pass-thru
Cost recovery via rider (RR)RR RR RR RR RR
<= Annual recovery Annual Qtr Qtr Qtr electric, Monthly gas Monthly
Energy Efficiency ++++Recovery of program costs Recovery of program costs Recovery of program costs Recovery of program costs Recovery of program costs None yet
Recovery of lost revenues Recovery of lost revenues Recovery of lost revenues Recovery of lost revenues Recovery of lost revenues
Earnings incentives Earnings incentives Pending before Commission Earnings incentives Earnings incentives
Commission =Appointed Appointed Appointed Elected Appointed Appointed
Treatment of Capital Projects

Source: RBC Capital Markets, Company reports
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IDA Regulatory Matrix
Regulatory Structure Elements
Blended
Rating Our Preferred Model ID ~95% net income
General Rate Cases
Test Year =Forward-looking Forward-looking
Allowed ROE ->10.5%, banded 9.5% floor
Frequency & Duration -File every 2-3 years Filed as needed
<6 month decision process 9-12+ months
Success rate ->60%45%
(% of request approved)
Other Regulatory Elements
Decoupling =Energy-efficiency-only Almost full decoupling
Other Recovery Rechanisms (non-
rate case)
=The more the better Fuel, Load Growth, Fixed Cost Adjustments
Treatment of Capital Projects ++++Long-term planning process Integrated Resource Plan
Commission Pre-approval Certificate of Public Convenience & Necessity
Recovery of AFUDC Open to CWIP, untested
Cost recovery via rider Included in base rates
Fuel and Purchased Power -100% pass-thru Pass-thru with 95/5 sharing of over/under
Cost recovery via rider (RR)Cost recovery outside of base rates
<= Annual recovery Reconciliation annually
Energy Efficiency =Recovery of program costs Recovery of program costs
Recovery of lost revenues Decoupled for lost revenues
Earnings incentives No earnings incentive
Commission =Appointed Appointed
Source: RBC Capital Markets, Company reports
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23

NEE Regulatory Matrix
Regulatory Structure Elements Rating Our Preferred Model* FL ~50% net income
General Rate Cases:
Test Year ++++Forward-looking Forward-looking
Allowed ROE —>10.5%, banded 10%, banded until 2012
Frequency & Duration =File every 2-3 years Filed as needed
<6 month decision process Year+ 2009, 6 months 2005
Success rate —>60%7.5% 2010
(% of request approved)
Other Regulatory Mechanisms
Decoupling =Energy-efficiency-only None
Other Recovery Rechanisms (non-rate case)++++The more the better Fuel, Environmental Compliance,
Energy Efficiency, Renewables,
Capacity
Treatment of Capital Projects ++++Long-term planning process 10yr site plan
Commission Pre-approval Determinination of Need
Recovery of AFUDC Nuclear AFUDC, development
costs
Cost recovery via rider Rider recovery
Fuel and Purchased Power =100% pass-thru 100% pass-thru
Cost recovery via rider Cost recovery via rider
<= Annual recovery Annual
Energy Efficiency —Recovery of program costs Recovery of program costs
Recovery of lost revenues No recovery
Earnings incentives No Earnings incentives
Commission ++++Appointed Appointed
Source: RBC Capital Markets, Company reports
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24

NVE Regulatory Matrix
Regulatory Structure Elements Rating Our Preferred Model NV - 100%
General Rate Cases:
Test Year —Forward-looking Hybrid
Allowed ROE =>10.5%, banded 10.5%, unbanded
Frequency & Duration ++++File every 2-3 years Filed every 3 years
<6 month decision process 6 months
Success rate ++++>60%73% blended in 2007/2008
(% of request approved)
Other Regulatory Elements:
Decoupling ++++Energy-efficiency-only Energy-efficiency-only
Other Recovery Mechanisms (non-
rate case)
The more the better Energy efficiency, fuel
Treatment of Capital Projects =Long-term planning process Integrated Resource Plan (IRP)
Commission Pre-approval Through IRP
Recovery of AFUDC CWIP in rate base for critical facilities
Cost recovery via rider Recovery in base rates
Fuel and Purchased Power ++++100% pass-thru 100% pass-thru
Cost recovery via rider (RR)RR
<= Annual recovery Quarterly adjustments, annual true-up
Energy Efficiency ++++Recovery of program costs Recovery of program costs
Recovery of lost revenues Recovery of lost sales revenue
Earnings incentives Earnings incentives
Commission ++++Appointed Appointed
Source: RBC Capital Markets, Company reports
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25

PNM Regulatory Matrix
Regulatory Structure Elements Rating Our Preferred Model* NM - 75% rate base TX - 20% rate base
General Rate Cases
Test Year =Forward-looking Forward-looking Historical
Allowed ROE =>10.5%, banded 10.50%10.30%
Frequency & Duration of rate cases =File every 2-3 years Filed as needed Filed as needed
<6 month decision process 9 months 2009, >1 yr 2008 6 months
Success rate (% of request that is approved)=>60% 69% in 2009, 44% in 2008 52% in 2009
Other Regulatory Elements
Decoupling ++++Energy Efficiency-only Energy Efficiency-only None
Recovery Mechanisms outside of general
rate case process
=The more the better Fuel, Energy Efficiency Purchased power
Treatment of Large Capital Projects ++++Pre-approval by Commission Certificate of Public Convenience &
Necessity
N/A
Long-term planning Integrated Resource Plan
Recovery of AFUDC No recovery
Assurance of total cost recovery No assurance
Cost recovery outside of base rates Included in base rates
Fuel and Purchased Power =100% pass-thru 100% pass-thru 100% pass-thru
Cost recovery outside of base rates Cost recovery outside of base rates Cost recovery outside of base rates
Reconciliation at least annually Reconciliation annually Reconciliation annually
Energy Efficiency ++++Recovery of program costs Recovery of program costs AMI cost recovery plus return
Recovery of lost sales revenue Recovery of lost sales revenues
Earnings incentives Earnings incentives
Commission —Appointed Elected Appointed
Source: RBC Capital Markets, Company reports
SO Regulatory Matrix
Blended
Regulatory Elements Our Preferred Model Rating GA ~47% net income AL ~34% net income MS ~5% net income FL ~5% net income
General Rate Cases
Test Year Forward-looking ++++Forward-looking Forward-looking Forward-looking Forward-looking
Allowed ROE >10.5%, banded ++++11.25%, banded 13.0-14.5%, banded Banded, above 13%11%
Frequency & Duration File every 2-3 years ++++
Filed every 3 years Annual RSE filings Annual PEP filing Filed as needed
<6 month decision process 6 months ~1 month ~1 month 9 months
Success rate >60%=70% settlement pending N/A N/A 75% in 2001
(% of request
approved)
Other Regulatory Mechanisms
Decoupling Energy-efficiency-only =None None None None
Other Recovery
Mechanisms (non-rate
case)
The more the better ++++Fuel, Environmental Compliance
costs, Natural Disaster reserve
Fuel, New Capacity, Environmental
compliance, Natural Disaster reserve
Fuel, Environmental compliance Fuel, Environmental Compliance,
Energy Efficiency, Renewables
Treatment of Capital
Projects Long-term planning process
++++
Integrated Resource Plan None Integrated Resource Plan 10yr site plan
Commission Pre-approval Certificate of Need Rate Certification New Plant Certificate of Need Determinination of Need
Recovery of AFUDC Recovery for nuclear O&M, depreciation, ROI CWIP recovery AFUDC, development costs
Cost recovery via rider Recovery in Rate Base Rider recovery Rider recovery Rider recovery
100% pass-thru =100% pass-thru 100% pass-thru 100% pass-thru 100% pass-thru
Cost recovery via rider (RR)RR RR RR RR
<= Annual recovery Annual Annual Annual Annual
Energy Efficiency Recovery of program costs =Recovery of program costs No mandates No mandates Recovery of program costs
Recovery of lost revenues No recovery No recovery
Earnings incentives Return on program costs No Earnings incentives
Commission Appointed —Elected Elected Elected Appointed
Fuel and Purchased
Power

Source: RBC Capital Markets, Company reports
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26

TE Regulatory Matrix
Regulatory Structure Elements Rating Our Preferred Model* 100% Florida
General Rate Cases
Test Year ++++Forward-looking Forward-looking
Allowed ROE =>10.5%, banded 11.20%
Frequency & Duration of rate cases —File every 2-3 years Filed as needed
<6 month decision process 8-9 months
Success rate (% of request that is approved)++++>60%62% in 2009
Other Regulatory Elements
Decoupling =Energy Efficiency only None
Recovery Mechanisms outside of general rate
case process
++++The more the better Fuel, Environmental compliance, Capacity costs,
Energy efficiency, storm damage
Treatment of Capital Projects ++++Pre-approval by Commission Determination of Need
Long-term planning 10yr site plan, filed every 3 years
Recovery of AFUDC Recovery of AFUDC, development costs
Assurance of total cost recovery Costs approved, recovery not guaranteed
Cost recovery outside of base rates Capacity Cost Recovery Clause
Fuel and Purchased Power =100% pass-thru 100% pass-thru
Cost recovery outside of base rates Cost recovery outside of base rates
Reconciliation at least annually Reconciliation annually
Energy Efficiency =Recovery of program costs Recovery of program costs
Recovery of lost sales revenue No recovery of lost sales revenues
Earnings incentives No earnings incentives
Commission ++++Appointed Appointed
Source: RBC Capital Markets, Company reports
UTL Regulatory Matrix
Blended
Regulatory Elements Rating Our Preferred Model NH ~50%MA ~25%ME ~25%
General Rate Cases:
Test Year —Forward-looking Historical Historical Historical
Allowed ROE —>10.5%, banded 9.67%10-10.25%NM
Frequency & Duration =File every 2-3 years File as needed File as needed File as needed
<6 month decision process 3/9 months, stepped ~1 month ~9 months
Success rate +>60%80%64%N/A
(% of request approved)
Other Regulatory Mechanisms
Decoupling =Energy-efficiency-only None In next rate case None
Other Recovery Rechanisms
(non-rate case)
=The more the better Fuel, Storm Reserve Fuel Fuel
Treatment of Capital =Long-term planning process None None None
Projects Commission Pre-approval Step adjustment proposed
Recovery of AFUDC
Cost recovery via rider
Fuel and Purchased Power =100% pass-thru 100% pass-thru 100% pass-thru 100% pass-thru
Cost recovery via rider (RR)RR RR RR
<= Annual recovery 6/12 months Annual Annual
Energy Efficiency =Recovery of program costs Recovery of program costs Recovery of program costs Recovery of program costs
Recovery of lost revenues None Decoupled in next rate case None
Earnings incentives Return on program costs Return on program costs Return on program costs
Commission +Appointed Appointed Appointed Appointed
Source: RBC Capital Markets, Company reports

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27
Appendix C: Environmental Regulations on the Horizon
Clean Water Act Section 316(b): Cooling Water Intake Structures
Requires that cooling water intake structures minimize adverse environmental impacts
• Parts of the rule were overturned by the U.S. Court of Appeals in 2007
• EPA proposed replacement rule in September
• Costs and benefits of controls may be considered
• Anticipated Implementation period: beginning in 2014, lasting five years
Impacts coal, gas, and nuclear plants
Solutions: Mesh netting systems, cooling towers
Cooling towers estimated to cost $170-$440/gallons per minute according to NERC

Maximum Available Control Technology (MACT) under Clean Air Act
Average emission limitation achieved by the best performing 12% of the existing sources
• Must propose MACT rule by March 16, 2011, finalize by November 16, 2011
• Mandatory three-year compliance timeframe
Impacts coal and oil-fired plants
Solutions: Scrubbers for all coal types plus Selective Catalytic Reduction controls (SCRs) for bituminous coal and Activated Carbon
Injection (ACI) & Baghouses for sub-bituminous and lignite coals
On average, ACI/Baghouses cost $150/kw, Scrubbers $400-$600/kw, SCRs $350-$500/kw

Clean Air Transport Rule (CATR)
To control long-range transport of power plant SOx/NOx emissions
• Draft rule proposed July 2010, finalize March 2011
• Proposed cap and trade program to start 1/1/2012, stricter compliance level starting in 2014
Impacts mostly eastern U.S. coal plants
Solutions: Scrubbers and SCRs

Coal Combustion Residuals (CCR)
Coal ash disposal parameters to protect groundwater
• Draft rule proposed May 2010, final rule expected in 2011
• Compliance to start 2013-2015, full compliance by 2018
Impacts coal plants with wet storage ash ponds
Solutions: Dry landfill storage rather than wet ash pond storage
Costs for conversion are site-specific, but range from $100-$150 per location

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